Selectively controlling fluid flow through the higher permeability zones of subterranean reservoirs

ABSTRACT

A method for restricting fluid flow in depth outwardly from the bore hole through the medium to high permeable zones of a subterranean reservoir of nonuniform permeability in which there is injected into the reservoir aqueous solutions of a water-soluble polymer and an alkali metal silicate. The injected solutions are either admixed at the surface prior to injection, simultaneously injected or injected sequentially.

BACKGROUND OF THE INVENTION

1. Field of the Invention

This invention relates to a method for restricting fluid flow throughthe medium to high permeable strata of subterranean reservoirs havingheterogeneous permeability at a substantial depth outwardly from a borehole. More particularly, the invention relates to such a method toprovide better control of fluids subsequently injected into a reservoirduring enhanced oil recovery operations or withdrawn from a reservoirduring production operations.

2. Description of the Prior Art

When fluids flow through reservoirs having sections of varyingpermeability, a higher percentage of the fluids tends to flow throughthose sections having a higher permeability. It is often desired todecrease or stop the flow of fluids through these sections of higherpermeability.

For example, in the enhanced recovery of petroleum by flooding, adisplacing fluid is injected into the reservoir via one or moreinjection wells to displace the petroleum through the reservoir towardone or more producing wells.

In the normal flooding operation, maximum oil recovery is obtained whenthe driven fluid builds up in a wide band in front of the driving fluidwhich moves uniformly towards the producing well. To keep this bank ofoil intact, and constantly moving towards the producing well, asubstantially uniform permeability must exist throughout the reservoir.If this uniform permeability does not exist, or is not provided, theflooding fluid will follow the path of least resistance, pass mostlythrough the portions of the reservoir having the highest permeabilityand bypass the petroleum present in the less permeable portions of thereservoir. This results in the loss of some driving fluid energy and theearly appearance of excessive amounts of driving fluid at the producingwell. If fluid flow through these high permeability zones of thereservoir was restricted or they were plugged, the injected fluid wouldbe forced to flow into the less permeable portions of the reservoir anddisplace a higher percentage of the petroleum present in the entirereservoir. Similarly, in the production of oil, producing wellssometimes produce water and/or gas along with oil. The water and gasoften are produced through the portions of the reservoir having arelatively high permeability. If the zones through which water and gasare produced could be at least partially plugged, a higher percentage ofthe produced fluids would be the desired oil phase.

A wide variety of materials have been proposed for use in pluggingsubterranean reservoirs. It is known to inject an aqueous solution of awater-soluble polymer and a cross-linking agent which reacts in thereservoir to form a plug. Similarly, plugs have been formed usingaqueous solutions of sodium silicate and a gelling agent therefor. U.S.Pat. No. 4,069,869 to Sandiford described a method for forming a mixedplug in a reservoir by injecting aqueous solutions of: (1) a polymersuch as polyacrylamide, polysaccharide or a cellulose ether, (2) across-linking agent such as sodium dichromate which reacts with thepolymer to form a time-delayed polymer-containing plug, (3) an alkalimetal silicate such as sodium silicate, and (4) a gelling agent such asammonium sulfate which reacts with the silicate to form asilicate-containing plug. The injected compositions are either admixedat the surface or injected simultaneously. U.S. Pat. No. 4,009,755 toSandiford discloses a method for forming a combination plug usingmaterials similar to those described in the previous Sandiford patentwherein there is injected into a reservoir aqueous solutions of apolymer and a cross-linking agent which react to form a first plugfollowed by an aqueous solutions of an alkali metal silicate and agelling agent which react to form a second plug.

The various plug-forming compositions and methods previously suggestedhave met with some success, especially in reducing fluid flow throughthe highest permeability channels of heterogeneous reservoirs whichrequire formation of a very stiff gel or solid, i.e., the type of plugbest provided by a plug-forming composition including either across-linking agent or a gelling agent. However, need remains for evenmore effective methods for forming plugs, especially in reservoirshaving channels or zones of high to medium permeability where a verystiff gel or solid plug is not required or sometimes not even desired. Astiff gel or solid plug may adequately plug a portion of a very highpermeability channel, but, after formation, the plug has little abilityto continue to move or flow and may be bypassed by other low viscosityfluids flowing through the reservoir. Thus, it has been difficult toform in the higher permeability channels of a reservoir a material whichrestricts fluid flow through that portion of the reservoir, but whichfluid flow-restricting material remains capable of at least limited flowitself when occupying a channel to which a pressure differential isapplied so that it is not so easily bypassed by other fluids.

One especially troublesome type of reservoir of heterogeneouspermeability in which to carry out enhanced recovery operations is onein which any injected treating fluid, such as a plug-formingcomposition, takes a relatively long period of time to travel from aninjection well to a production well. Travel time can be as long as onemonth, two months or even longer. High permeability channels often existover the entire distance between wells. Plug-forming compositionscontaining cross-linking agent and/or a gelling agent tend to form plugswithin a relatively short period of time, as within 24 hours after beinginjected. Also many cross-linking agents and gelling agents exhibit atendency to adsorb onto reservoir rock so that such compositions whichhave passed through the reservoir only a limited distance away from theinjection bore hole become partially, substantially or completelydepleted of cross-linking agent or gelling agent. Thus, due to severalfactors it is difficult to form a plug a substantial distance from theinjection bore hole.

Accordingly, a principal object of this invention is to provide a methodfor controlling the permeability of a subterranean formation ofnonuniform permeability.

Another object of the invention is to provide a method for reducingchanneling of a flooding medium from an injection well to a producingwell via a zone of high to medium permeability.

Still another object of the invention is to provide a method forselectively restricting fluid flow through water-producing andgas-producing zones in a subterranean reservoir.

A further object of the invention is to restrict fluid flow through thehigher to medium permeability zones of a reservoir at a substantialdistance from the injection bore hole.

A still further object of the invention is to achieve an in depthrestriction of fluid flow through the medium to high permeability zonesof a reservoir.

Other objects, advantages and features of the invention will becomeapparent from the following description and appended claims.

SUMMARY OF THE INVENTION

A method for restriction fluid flow through the zones of a subterraneanreservoir penetrated by a well having medium to high permeability,especially at a substantial depth away from the bore hole in suchreservoirs, to control the path of flow of fluids through the reservoirin which there is injected or introduced into the reservoir an aqueoussolution or dispersion of a water-soluble polymer and an aqueoussolution or dispersion of an alkali metal silicate. The components areinjected in a manner such that they are or become mixed when in thereservoir, i.e., they are either permixed at the surface prior toinjection, injected simultaneously or injected sequentially.

DETAILED DESCRIPTION OF THE INVENTION

When an enhanced oil recovery fluid is injected into a reservoir it isdesired that it pass therethrough in as uniform a manner as possible. Inreservoirs having heterogeneous permeability, such fluid tends to flowprimarily through the more permeable flow channels, finger through thereservoir and largely bypass the less permeable strata which may make upthe bulk of the reservoir and contain a large proportion of the oilwhich it is desired to displace. Thus, prior to the injection of theenhanced oil recovery fluid, it is desired to restrict fluid flowthrough or plug those more permeable flow channels so that such recoveryfluid, when introduced, will have more of a tendency to travel throughand displace oil from the less permeable strata. Due to the complexnature of reservoirs encountered, there are a wide variety ofheterogeneous permeability conditions with which to deal. In order torestrict fluid flow through channels of very high permeability, it isgenerally necessary to utilize a treating agent which will form a verystiff gel or solid. Plug-forming compositions made up of a polymertogether with a cross-linking agent and/or an alkali metal silicatetogether with a gelling agent are often employed in such situations. Forchannels which are only slightly higher in permeability than the rest ofthe reservoir, an aqueous polymer solution often provides enough effecton fluid flow to even out flow of an enhanced oil recovery fluidtherethrough. Need remains for a more effective method for restrictingfluid flow through channels having a permeability between those having avery high permeability and those having a permeability only slightlyhigher than the rest of the reservoir. Broadly, these channels ofso-called medium permeability have a permeability of about 50 to 1,000millidarcys. Since these more permeable flow channels often existthroughout the entire segment of the reservoir penetrated by therecovery fluid, it is desirable to form the plug over the entiresegment, i.e., the plug-forming composition must be capable ofrestricting fluid flow or plugging the reservoir throughout the segmentas well as in the immediate vicinity of the well bore. Many present daypolymer plugging treatments are designed to form a plug up to 25 feetaway from the injection well. Following the method of this invention,the fluid flow through the reservoir can be restricted at a depth ofmore than 25 feet from the well e.g., 35 to 100 feet or more.

It has been found possible to carry out such an operation to restrictfluid flow by injecting into the reservoir an aqueous solution of awater-soluble polymer and an aqueous solution of an alkali metalsilicate. When mixed, these compositions form a high viscosity fluidcomposition having some slight evidence of a gel structure which, whenoccupying a flow channel, restricts flow of another fluid therethrough,even though substantially free of a cross-linking agent and a gellingagent which have previously been employed. By controlling theconcentration of the polymer and the silicate, the flow restriction canbe made to occur at any desired time, e.g., at any time after injectioninto the reservoir. By the proper selection of concentration ofcomponents and injection procedures, the fluid flow restricting mixturecan be made to become effective at times of two weeks to two months ormore after injection into the reservoir.

The flow-restricting mixture can be prepared in any of a number of ways.The polymer and alkali metal silicate can be admixed with water or brinein any order at the surface. An aqueous solution of the polymer and anaqueous solution of the alkali metal silicate can be prepared separatelyand mixed before being injected down a well conduit. The polymer andalkali metal silicate can be blended into water or brine as the latteris being injected down a well conduit. The separately prepared aqueoussolutions can be injected simultaneously down a well so that they mix asthey travel down the well conduit. Alternatively, the separatelyprepared mixtures can be injected down the well conduit sequentially inany order so that they contact each other and mix after they haveentered and are passing through the reservoir.

The aqueous polymer solution employed in the treatment of this inventionis a dilute solution of a water-soluble or water-dispersible polymer infresh water or brine. A number of water-soluble polymers are known toform viscous aqueous polymer solutions when dissolved therein inrelatively dilute concentrations. Exemplary water-soluble polymericmaterials that can be employed are relatively high molecular weightacrylic acid-acrylamide copolymers; polyacrylamides; partiallyhydrolyzed polyacrylamides; terpolymers of acrylamide and substitutedacrylamides, such as acrylamide polymerized with various combinations ofN,N'-methylenebisacrylamide, N-tert-butylacrylamide, methylolacrylamideand N-isopropylacrylamide, and terpolymers of acrylamide, acrylic acidand acrylonitrile; polyalkleneoxides and heteropolysaccharides obtainedby the fermentation of starch-derived sugar.

Many of the water-soluble polymers useful in the practice of thisinvention are characterized by a viscosity of at least 3 centipoises fora 0.1 percent by weight solution thereof in aqueous 3 percent by weightsodium chloride solution at 25° C. as determined with a Brookfieldviscometer equipped with a UL adapter and operated at a speed of 6r.p.m. However, it is to be recognized that other of the water-solublepolymers, such as certain polyacrylamides and polyalkyleneoxides, areeffective in reducing the mobility of water in porous media, yet havelittle or only slight effect upon the viscosity of water or brine.

The polyacrylamide and partially hydrolyzed polyacrylamide which can beused in this invention include the commercially available,water-soluble, high molecular weight polymers having molecular weightsin the range of above about 0.2×10⁶ , preferably from 0.5×10⁶, and morepreferably from 3×10⁶ to 10×10⁶. The hydrolyzed polyacrylamides have upto about 70 percent of the carboxamide groups originally present in thepolyacrylamide hydrolyzed to carboxyl groups. Preferably from about 12to about 45 percent of the carboxamide groups are hydrolyzed to carboxylgroups. Hydrolysis of the acrylamide is accomplished by reacting thesame with sufficient aqueous alkali, e.g., sodium hydroxide, tohydrolyze the desired number of amide groups present in the polymermolecule. The resulting products consist of a long hydrocarbon chain,with some carbon atoms bearing either amide or carboxyl groups.Copolymerization of acrylic acid and acrylamide according to well knownprocedures produces acrylic acid-arylamide copolymers. The term"hydrolyzed polyacrylamide," as employed herein, is inclusive of themodified polymers wherein the carboxyl groups are in the acid form andalso of such polymers wherein the carboxyl groups are in the salt form,provided that the salts are water-soluble. Alkali metal and ammoniumsalts are preferred. A number of polyacrylamides and partiallyhydrolyzed acrylamide polymers and acrylic acid-acrylamide copolymerssuitable for use in this invention are commercially available; forexample, WC-500 polymer marketed by Calgon Corporation of Pittsburgh,Pa., Pusher 700 polymer marketed by The Dow Chemical Company of Midland,Michigan, Q-41-F polymer marketed by Nalco Chemical Company of OakBrook, Illinois and Cyantrol 940 polymer marketed by American Cyanamidof Wayne, N.J.

Especially useful in the practice of this invention are the partiallycationic polyacrylamides, the partially anionic polyacrylamides andmixtures thereof. A partially cationic polyacrylamide is a nonionicpolyacrylamide which contains a cationic co-monomer, such as an alkylenepolyamine, a quaternary ammonium chloride or amine hydrochloride, forexample trimethyl octyl ammonium chloride, trimethyl stearyl ammoniumchloride, oleyl trimethyl ammonium chloride, oleyl amine diethylaminehydrochloride and dimethylaminopropylamine. A partially anionicpolyacrylamide can be a nonionic polyacrylamide which has been partiallyhydrolyzed to convert some of the acrylamide groups to acrylic groups,the alkali metal salts of which are anionic. Introducing sulfate orsulfonate groups into the polyacrylamide molecule also imparts ananionic character to the molecule. Polymer 1160 is a 20 percent byweight cationic, 80 percent nonionic copolymer marketed by BetzLaboratories, Inc. of Trevose, Pa. Polymer 1120 and Hi Vis polymer are35 percent anionic, 65 percent nonionic polyacrylamides which have beenpartially hydrolyzed to the extent of 35 percent. These polymers arealso marketed by Betz Laboratories, Inc. Also suitable are cationicpolymers N-Hance 210 and 220 and anionic polymers N-Hance 325 and 1031marketed by Cort Company of Bartlesville, Oklahoma.

The operable polyalkeneoxides have molecular weights in the range offrom about 10⁵ to about 10⁸, preferably from 10⁶ to 10⁷ and mostpreferably from 3×10⁶ to 10×10⁶. By "polyalkeneoxide" is meant hereinany of the polymeric water-soluble resins prepared by homopolymerizationof a single alkene oxide, for example ethylene oxide, propylene oxide orbutylene oxide. It is preferred to employ the homopolymer ofpolyethylene oxide. This product is marketed by Union Carbide ChemicalsCompany of New York City, New York under the trademark "Polyox". Mixedpolyalkeneoxides, made by heteropolymerization of more than one alkeneoxide in either a random or block polymerization, may also be employed.

The heteropolysaccharides which may be used in carrying out the presentinvention are ionic polysaccharides produced by fermentation ofcarbohydrates by bacteria of the genus Xanthomonas. Examples of suchheteropolysaccharides are those produced by Xanthomonas campestris,Xanthomonas begonia, Xanthomonas phaseoli, Xanthomomonas hederae,Xanthomonas incanae, Xanthomonas carotae and Xanthomonas translucens. Ofthese, ionic polysaccharide B-1459 is preferred. The polysaccharideB-1459 is prepared by culturing the bacterium Xanthomonas campestrisNRRL B-1459, U.S. Department of Agriculture, on a well aerated mediumcontaining commercial glucose, organic nitrogen sources, dipotassiumhydrogen phosphate and various trace elements. Fermentation is carriedto completion in four days or less at a pH of about 7 and a temperatureof 28° C. Polysaccharide B-1459 is available under the trademark KelzanMF marketed by Kelco Company of San Diego, CA. Production of thisheteropolysaccharide is well described in Smiley, K. L. "MicrobiolPolysaccharides--A Review," Food Technology 20 9:112-116 (1966), andMoraine, R. A., Rogovin, S. P. and Smiley, K. L. "Kinetics ofPolysaccharide B-1459 Synthesis," J. Fermentation Technology 44, 311-312(1966).

The selected water-soluble polymer is admixed with fresh water or brineto provide a relatively dilute aqueous solution of the polymer thatexhibits a sufficiently reduced mobility when injected into the porousmedia to divert subsequently injected fluids to the less permeablechannels. Preferably, the polymer is dissolved in fresh water since themobility reduction effect of most of these polymers is inhibited by thepresence of substantial quantities of dissolved salts. However, it issometimes desirable to employ oil-field brine or other water containingrelatively high dissolved salt contents, particularly where thereservoir into which they are to be injected is water-sensitive or wherefresh water is not available. In most instances, the mobility of thewater can be reduced to the desired level by the addition of about 0.001to about 1 weight percent of the polymer, and satisfactory results canoften be obtained by the addition of 0.05 to 0.15 weight percent ofpolymer.

The alkali metal silicate is employed in a dilute aqueous solution infresh water or light brine, preferably fresh water. Sodium silicate isthe most widely used silicate. The ratio of silica to sodium oxide inthe silicate can vary within limits from about 1.5:1 to about 4:1 byweight. Preferably the ratio should be from about 3:1 to about 3.5:1.Potassium silicate can be used in place of sodium silicate, although thegreater cost of potassium silicate limits its use. Mixtures of sodiumsilicate and potassium silicate are sometimes preferred because of thelow viscosity of their aqueous solutions. Sodium silicate is usuallymarketed as a concentrated thick aqueous solution or as a powder. Adilute aqueous solution can be formed by mixing either form withadditional fresh water or brine.

The concentration of alkali metal silicate in the flow-restrictingsolution can vary over a wide range. Less flow-restriction is achievedat the more dilute concentrations and costs are often excessive athigher concentrations. Thus, it is preferred that the alkali metalsilicate concentration of the flow-restricting solution injected intothe formation be between about 0.05 and 5 weight percent and preferablybetween about 0.1 and 1.5 weight percent.

The aqueous solutions of polymer used in the practice of this inventionhave a viscosity of about 5 to 100 centipoises. The aqueous solutions ofalkali metal silicate employed have a viscosity of about 1.5centipoises. It is sometimes desirable to inject these two compositionsseparately and have them mix in the reservoir. Since the flow rate of asolution through the reservoir depends in part on its viscosity, it issometimes desirable to add a thickener to the aqueous solution of alkalimetal silicate so that its viscosity approximately equals that of theaqueous solution of polymer. The two solutions then tend to flow throughthe reservoir at about the same rate and chances of their mixing areimproved. Thus, it is optional to add to the aqueous solution of alkalimetal silicate a cellulose ether thickening agent. The cellulose etherdoes not react with either the polymer or the silicate and thus does notassist in forming the plug. Generally from about 0.05 to 1 weightpercent cellulose ether, preferably 0.1 to 0.3 weight percent, is aneffective amount giving the required thickening effect.

In general, any of the water-soluble cellulose ethers can be used in thepractice of the invention. Cellulose ethers which can be used include,among others; mixed ethers such as carboxyalkyl hydroxyalkyl ethers,e.g., carboxymethyl hydroxyethyl cellulose (CMHEC); hydroxyalkylcelluloses such as hydroxyethyl cellulose, and hydroxypropyl cellulose;alkylhydroxyalkyl celluloses such as methylhydroxypropyl cellulose;alkylcarboxyalkyl celluloses such as ethylcarboxymethyl cellulose; andhydroxyalkylalkyl celluloses such as hydroxypropylmethyl cellulose; andthe like. Many of the cellulose ethers are available commercially invarious grades.

The carboxy-substituted cellulose ethers are available as the alkalimetal salt, usually the sodium salt. However, the alkali metal is seldomreferred to and they are commonly referred to CMHEC, etc. In theabove-described mixed ethers, it is preferred that the portion thereofwhich contains the carboxylate groups be substantial instead of a meretrace. For example, in CMHEC it is preferred that the carboxymethyldegree of substitution be at least 0.4. The degree of hydroxyethylsubstitution is less important and can vary widely, e.g., from about 0.1or lower to about 0.4 or higher. Hydroxyalkyl celluloses are preferred,particularly hydroxyethyl cellulose.

While the volume of flow restricting fluid mixture to be employed intreating a reservoir can vary widely depending on the nature of thereservoir, generally a mixture containing about 1 to 100 barrels pervertical foot of strata to be treated of an aqueous polymer solution ordispersion and about 1 to 100 barrels per vertical foot of strata to betreated of an aqueous alkali metal silicate solution or dispersion willprovide the required flow restriction. The mixture of components shouldcontain about 25 to 75 parts by weight of an aqueous solution of apolymer and about 75 to 25 parts by weight of an aqueous solution of analkali metal silicate. Preferably about equal amounts of each componentare injected to form the mixture. It is to be understood that the methodof this invention is often employed as one step in an overall enhancedoil recovery or other process. Thus, the injection of the compositionsof the method of this invention can be preceeded and/or followed by theinjection of various other treating fluids or drive fluids such asaqueous polymer solutions, plug-forming solutions and the like.

The invention is further described by the following examples which areillustrative of specific modes of practicing the invention and are notintended as limiting the scope of the invention as defined by theappended claims.

EXAMPLE 1

The two flat end surfaces of a 3 inch long, 41/4 inch diametercylindrical core from a California well are coated with a fluid plasticwhich sets to form a solid through which fluid cannot be injected. A21/2 inch long hole having a diameter of 3/16 inch is axially drilledinto the top end of the core. The core is vertically mounted in aconfining vessel of slightly larger dimensions than the core whichconfining vessel has a first fluid entry port in the top and a secondfluid entry port in the bottom in communication with the annular spacebetween the core and the confining vessel, and a third entry port in thetop in communication with a tube the other end of which extends into theconfining vessel and into fluid tight engagement with the hole drilledin the core. The permeability of the core to water is 53 millidarcys.

Phase 1: The core is saturated with a synthetic brine made to match thecomposition of the brine from the California well by flowing the saidbrine into the confining vessel via the second fluid entry port thereinand through the core while pulling a vacuum on the third fluid entryport. The water is then drained from the confining vessel.

Phase 2: The core is saturated with a mineral oil having a viscosity of45.8 centipoises, the same as the viscosity of the crude oil from thewell, by pumping the mineral oil into the confining vessel via the firstentry port and allowing it to flow out of the third entry port at apressure differential of 15 p.s.i.g.

Phase 3: The core is waterflooded to a water/oil ratio of 49 by passingthrough the core the same synthetic brine as used in Phase 1 using thesame procedure as used in Phase 2. A pressure differential of 15p.s.i.g. is used.

Phase 4: In an attempt to recover additional oil, the core is subjectedto a polymer flood by injecting therethrough by the procedures of Phase2, a pressure differential of 15 p.s.i.g., about 2 pore volumes of anaqueous solution of the above-described synthetic brine containing 0.1percent by weight of a polyacrylamide marketed by American CyanamidCompany under the trademark Cyanatrol 950-S.

Phase 5: In a further attempt to recover additional oil and control theproduced water/oil ratio by restricting fluid flow through or pluggingthe more permeable channels of the core, there is injected into the coreby the procedures of Phase 2 at a flow rate of 0.53 ml/min. and apressure differential of 15 p.s.i.g., about 1 pore volume of an aqueoussolution of the above-described synthetic brine containing 0.1 percentby weight Cyanatrol 950-S polyacrylamide and 0.5 percent by weight ofsodium silicate marketed by Philadelphia Quartz Company under thetrademark N-brand sodium silicate. The aqueous solution was prepared byadding both the polymer and the sodium silicate to the brine andstirring.

Phase 6: Finally, there is injected into the core a fresh water polymerflood by the procedures of Phase 2 at a pressure differential of 15p.s.i.g. About 0.7 pore volume of an solution of 0.1 percent by weightCyanatrol 950-S polyacrylamide in fresh water is injected.

In this Example, each fluid passing through the core in a particularphase is drained from the confining vessel before introducing anotherfluid in the next Phase. Table I shows the results of this test. It isfound that when an aqueous polymer solution is injected (Phase 4)following the waterflood, the water/oil ratio drops sharply and a largeamount of additional oil is recovered. However, after 2 pore volumes ofaqueous polymer solution have been injected, no additional oil isrecovered and the water/oil ratio increases sharply. At this point themethod of the instant invention is carried out (Phase 5) by injecting anaqueous solution containing both polyacrylamide and sodium silicate.This treatment recovers a significant amount of additional oil while thewater/oil ratio at first increases and then decreases sharply. In Phase6, a slug of polymer in fresh water recovers still further additionaloil before a sharp rise in the water/oil ratio occurs.

                  TABLE I                                                         ______________________________________                                        RECOVERY OF ADDITIONAL OIL FROM A                                             CYLINDRICAL CORE BY INJECTING AN AQUEOUS                                      SOLUTION CONTAINING POLYACRYLAMIDE                                            AND SODIUM SILICATE                                                                             Cumulative                                                        Cumulative  Oil Recovered                                                                             Produced                                                                              Flow                                          Fluid Injected                                                                            (% Oil      Water/Oil                                                                             Rate                                    Phase (Pore Volume)                                                                             in Place)   Ratio   (ml/sec)                                ______________________________________                                        3     0.08        6.3         0.6     0.132                                   "     0.115       6.75        19      "                                       "     0.173       7.2         "       0.137                                   "     0.46        9           24      0.134                                   "     0.75        10.8        "       0.128                                   "     1.04        12.2        32.3    --                                      "     1.32        13.5        "       --                                      "     1.61        14.4        49      --                                      "     1.90        15.3        "       0.121                                   4     2.07        19.8        5       0.189                                   "     2.21        23.4        5.2     --                                      "     2.36        27          "       --                                      "     2.50        29.7        7.3     --                                      "     2.65        32          8.6     --                                      "     2.79        33.8        7.7     --                                      "     2.93        35.8        10.4    --                                      "     3.08        37.6        7.7     --                                      "     3.22        39.4        "       --                                      "     3.51        40.3        49      --                                      "     3.80        42.1        24      --                                      "     4.08        43.9        "       0.169                                   5     4.37        45.7        24      0.216                                   "     4.66        47.1        32.3    0.0154                                  "     4.95        48.9        24      0.0111                                  "     5.07        49.8        21      0.0089                                  6     5.35        50.7        49      0.0060                                  "     5.73        52.9        25      0.0053                                  "     5.88        53.8        26      0.0050                                  "     6.17        54.3        99      0.0054                                  ______________________________________                                    

EXAMPLE 2

A rectangular core from a California field measuring 3.5 inches × 1.75inches × 1.25 inches is fitted with a porous disk on each of the twoopposite end faces having the smallest surface area. The core containssome reservoir crude oil which has hardened somewhat due to exposure tothe atmosphere. The surfaces of the core and the porous disks are thencoated with a fluid plastic that sets to form a solid adherent surfaceimpervious to fluid flow. A centralized 0.125 inch diameter hole isdrilled into each of the two vertically positioned disk surfaces. Theholes are tapped for fluid injection. The permeability of the core towater is 450 millidarcys. Union's fluids are then flowed through thecore at the reservoir temperature of 125° F. and a pressure of 5p.s.i.g.

Phase 1: The hardened crude oil is removed by flowing about 10 porevolumes of kerosine through the core.

Phase 2: About four pore volumes of field crude oil is flowed throughthe core to saturate the core with crude oil.

Phase 3: The core is water flooded to a high water/oil ratio of 124 byinjecting about 5 pore volumes of reservoir water.

Phase 4: In an attempt to recover additional oil, the core is subjectedto a polymer flood by injecting therethrough about 1.5 pore volumes ofan aqueous solution of 0.1 percent by weight Cyanatrol 950-Spolyacrylamide in reservoir water.

Phase 5: In a further attempt to recover additional oil and lower theproduced water/oil ratio by restricting fluid flow in the medium to highpermeability channels of the core, there is injected into the core about1.75 pore volumes of an aqueous solution of reservoir brine containing0.1 percent by weight Cyanatrol 950-S polyacrylamide and 0.5 percent byweight N-brand sodium silicate. The aqueous solution is prepared byadding both the polymer and the sodium silicate to reservoir brine andstirring.

Phase 6: Finally there is injected into the core about 3 pore volumes ofthe same polymer flood as used in phase 4.

As is shown in Table II, it is found that when an aqueous polymersolution is injected (Phase 4) following the waterflood, the water/oilratio drops sharply at first but quickly increases again to anundesirably high value. About 5.6 percent additional oil is recovered.When the method of the instant invention is carried out (Phase 5) byinjecting an aqueous solution containing both polyacrylamide and sodiumsilicate, 20.7 percent additional oil is recovered, the water/oil ratiodecreases sharply and remains low, but the flow rate undesirablydecreases substantially. When another slug of polymer solution isinjected (Phase 6), 9.2 percent additional oil is recovered and the flowrate desirably goes up. However, the water/oil ratio undesirably goes upas well. Thus, the greatest amount of additional oil is recovered at adesirably low water/oil ratio using the method of the instant invention.

                  TABLE II                                                        ______________________________________                                        RECOVERY OF ADDITIONAL OIL FROM A                                             RECTANGULAR CORE BY INJECTING AN AQUEOUS                                      SOLUTION CONTAINING POLYACRYLAMIDE                                            AND SODIUM SILICATE                                                                             Cumulative                                                        Cumulative  Oil Recovered                                                                             Produced                                                                              Flow                                          Fluid Injected                                                                            (% Oil      Water/Oil                                                                             Rate                                    Phase (Pore Volume)                                                                             in Place)   Ratio   (ml/sec)                                ______________________________________                                        3     0.32        1.8         24      --                                      "     0.64        2.8         49      --                                      "     0.97        3.7         "       --                                      "     1.29        5.1         32      --                                      "     2.1         7.8         41      --                                      "     2.9         10.1        49      --                                      "     3.71        11.5        82      --                                      "     4.52        12.4        124     0.247                                   4     4.84        16.1        11.5    --                                      "     5.16        18.9        15.7    --                                      "     5.48        20.7        24      --                                      "     5.81        21.7        49      0.027                                   5     6.13        24.0        19      --                                      "     6.45        30.0        6.7     --                                      "     6.77        35.5        7.3     --                                      "     7.1         40.1        9       --                                      "     7.42        44.7        "       0.0023                                  6     7.74        49.3        9       --                                      "     8.07        51.6        19      --                                      "     8.39        53.5        24      --                                      "     8.71        54.4        49      --                                      "     9.03        55.3        "       --                                      "     9.36        56.2        "       --                                      "     9.68        57.2        "       --                                      "     10.0        58.1        "       --                                      "     10.32       58.5        99      0.00783                                 ______________________________________                                    

EXAMPLE 3

The method for restricting fluid flow through a reservoir is illustratedby the following field example. A California well having a depth of3,100 feet and penetrating a 200 foot thick oil-containing reservoir isused as an injection well in an enhanced oil recovery process. A wellprofile shows that a high permeability zone exists near the top of thepay zone. This is believed due, at least in part, to the plugging of thelower part of the pay zone with particulate materials from dirtyinjection water previously injected. The oil-containing reservoir in theimmediate vicinity of the well is cleaned by treating with a slug ofacid solution and high pressure steam. The pay zone is then treated witha slug of an aqueous solution of polyacrylamide and a cross-linkingagent in accordance with well known procedures in an attempt to plug theupper high permeability zone in the vicinity of the well. The reservoiris then subjected to a polymer flood by injecting 20 percent of thereservoir pore volume of an aqueous solution of a polyacrylamidepolymer. The concentration of the polymer in the injected solution isgraded, starting with 0.15 weight percent, ending with 0.02 weightpercent and averaging 0.08 weight percent polyacrylamide. Periodicallyan injection profile is run on the well. When the injection profileindicates that the polymer solution is passing through the pay zone in anonuniform manner, it is necessary to treat the reservoir in an attemptto straighten out the flood front which by now exists out in thereservoir a considerable distance from the injection well bore. Thus, inaccordance with the procedures of this invention there aresimultaneously injected down the well tubing and into the reservoir 175barrels of an aqueous solution containing 0.15 weight percent N-Hance325 partially hydrolyzed anionic polyacrylamide marketed by Cort Companyand 175 barrels of an aqueous solution containing 0.5 weight percentN-Brand sodium silicate. These compositions are then followed by anadditional volume of an aqueous solution of a polyacrylamide polymer.

The two injected solutions mix while traveling down the well tubing andare injected into and travel through the reservoir. In two months timewhen the injected mixture is calculated to have traveled about 2,000feet from the well bore, the mixture is effective in reducing fluid flowthrough the medium to high permeability channels which it occupies.Thus, subsequently injected polyacrylamide solution is forced into theless permeable channels. The enhanced oil recovery flood fluid front inthe reservoir smooths out, fingering is reduced and additional oil isswept toward a production well through which it is produced.

While particular embodiments of the invention have been described, itwill be understood that the invention is not limited thereto since manymodifications can be made and it is intended to include within theinvention any such embodiments as fall within the scope of the claims.

The invention having been thus described, I claim:
 1. A method forreducing the permeability of the medium to high permeability strata orchannels of a subterranean reservoir having heterogeneous permeabilitypenetrated by a well comprising injecting through said well and intosaid reservoir:(a) about 1 to 100 barrels per vertical foot of strata tobe treated of a first composition consisting essentially of an aqueoussolution or dispersion of a water-soluble relatively high molecularweight polymer selected from the group consisting of acrylicacid-acrylamide copolymers, terpolymers of acrylamides and substitutedacrylamides, polyacrylamides, partially hydrolyzed polyacrylamides,polyalkyleneoxides and heteropolysaccharides obtained by thefermentation of starch-derived sugar, and (b) about 1 to 100 barrels pervertical foot of strata to be treated of a second composition consistingessentially of an aqueous solution or dispersion of an alkali metalsilicate,such aqueous solutions or dispersions being injected in amanner such that they are mixed in the reservoir.
 2. The method definedin claim 1 wherein said water-soluble relatively high molecular weightpolymer is employed at a concentration of about 0.001 to 1 percent byweight of the aqueous solution.
 3. The method defined in claim 1 whereinsaid water-soluble relatively high molecular weight polymer is employedat a concentration of about 0.05 to 0.15 percent by weight of theaqueous solution.
 4. The method defined in claim 1 wherein said alkalimetal silicate is employed at a concentration of about 0.05 to about 5percent by weight of the aqueous solution.
 5. The method defined inclaim 1 wherein said alkali metal silicate is employed at aconcentration of about 0.1 to 1.5 percent by weight of the aqueoussolution.
 6. The method defined in claim 1 wherein said alkali metalsilicate is sodium silicate.
 7. The method defined in claim 1 whereinthe aqueous solutions are admixed at the surface prior to injection intothe well.
 8. The method defined in claim 1 wherein the aqueous solutionsare injected sequentially into the well.
 9. The method defined in claim1 wherein the aqueous solutions are injected simultaneously into thewell.
 10. The method defined in claim 1 wherein the aqueous solution ofan alkali metal silicate additionally contains an effective amount of acellulose ether thickener.
 11. The method defined in claim 10 whereinthe cellulose ether is hydroxyethylcellulose.
 12. The method defined inclaim 1 wherein the high to medium permeability strata have apermeability of about 50 to 1,000 milldarcys.
 13. The method defined inclaim 1 wherein the said aqueous solution or dispersion of awater-soluble relatively high molecular weight polymer and the saidaqueous solution or dispersion of an alkali metal silicate aresubstantially free of a cross-linking agent and a gelling agent.
 14. Themethod defined in claim 1 wherein the reduction in permeability takesplace at a distance of about 35 to 100 feet or more from the well. 15.The method defined in claim 1 wherein the reduction in permeabilitybecomes effective from about two weeks in two months or longer afterinjection into the reservoir.
 16. In a method for enhanced oil recoverywherein a drive fluid is injected into a reservoir having heterogeneouspermeability via one or more injection wells to displace oil toward oneor more production wells, the improvement which comprises reducing thepermeability of the medium to high permeability strata or channels ofsaid reservoir by interrupting the injection of the drive fluid toinject into the said injection well and into the said reservoir a slugof about 1 to 100 barrels per vertical foot of strata to be treated of afirst composition consisting essentially of an aqueous solution ordispersion of a water-soluble relatively high molecular weight polymerselected from the group consisting of acrylic acid-acrylamidecopolymers, terpolymers of acrylamides and substituted acrylamides,polyacrylamides, partially hydrolyzed polyacrylamides,polyalkyleneoxides and heteropolysaccharides obtained by by thefermentation of starch-derived sugar, and about 1 to 100 barrels pervertical foot of a second composition consisting essentially of anaqueous solution on dispersion of an alkali metal silicate, whichsolutions are substantially free of a cross-linking agent and a gellingagent, which solutions mix and pass through the reservoir to form at asubstantial distance from the injection well a fluid flow restrictingcomposition which remains capable of at least limited fluid flow throughthe reservoir.
 17. The method defined in claim 16 wherein saidwater-soluble relatively high molecular weight polymer is employed at aconcentration of about 0.001 to 1 percent by weight of the aqueoussolution.
 18. The method defined in claim 16 wherein said water-solublerelatively high molecular weight polymer is employed at a concentrationof about 0.05 to 0.15 percent by weight of the aqueous solution.
 19. Themethod defined in claim 16 wherein said alkali metal silicate isemployed at a concentration of about 0.05 to about 5 percent by weightof the aqueous solution.
 20. The method defined in claim 16 wherein saidalkali metal silicate is employed at a concentration of about 0.1 to 1.5percent by weight of the aqueous solution.
 21. The method defined inclaim 16 wherein said alkali metal silicate is sodium silicate.
 22. Themethod defined in claim 16 wherein the aqueous solutions are admixed atthe surface prior to injection into the well.
 23. The method defined inclaim 16 wherein the aqueous solutions are injected sequentially intothe well.
 24. The method defined in claim 16 wherein the aqueoussolutions are injected simultaneously into the well.
 25. The methoddefined in claim 16 wherein the aqueous solution of an alkali metalsilicate additionally contains an effective amount of a cellulose etherthickener.
 26. The method defined in claim 25 wherein the celluloseether is hydroxyethylcellulose.
 27. The method defined in claim 16wherein the high to medium permeability strata have a permeability ofabout 50 to 1,000 darcys.
 28. The method defined in claim 16 wherein thereduction is permeability takes place at a distance of about 35 to 100feet or more from the well.
 29. The method defined in claim 16 whereinthe reduction in permeability becomes effective from about two weeks totwo months or longer after injection into the reservoir.